Tullow Oil plc (Tullow), the independent oil and gas exploration and production group (Group), announces its Full Year Results for the year ended 31 December 2024. Details of a management presentation and webcast that will be held at 09:00 today are available on the last page of this announcement or visit the Group's website: www.tullowoil.com
Richard Miller, Interim Chief Executive Officer and Chief Financial Officer, Tullow Oil plc, commented:
"In 2024 we had a number of succeses but also some operational challenges, most notably with Jubilee production and a reserves revision, however there is now strong momentum within the business with a return to drilling at Jubilee, and the commencement of production optimisation and reserves maturation activities in Ghana. In addition a number of key achievements have recently been realised, including the resolution of the Ghana Branch Profits Remittance Tax arbitration which eliminated a material overhang, the repayment of our 2025 senior notes and as announced on 24 March, the signed binding heads of terms for the sale of our Gabonese assets for a cash consideration of $300 million. This will accelerate our deleveraging progress this year.
"I am clear on the levers required to unlock Tullow's full potential. The team remains fully focused on our near-term priorities; advancing our refinancing plan, reducing costs, optimising production activities at Jubilee and TEN, and driving reserve growth. We will continue to maintain our financial discipline and prioritise investments that add value and deliver high returns.
"Tullow's core strength as a trusted partner with a cash generative business and attractive assets with reserves growth opportunities positions us well as we lay the foundations for value creation."
2024 FULL YEAR RESULTS
· Group working interest oil and gas production averaged 61.2 kboepd (2023: 62.7 kboepd).
· Revenue of $1,535 million (2023: $1,634 million), including $74 million hedge costs (2023: $139 million).
· Capital expenditure1 of $231 million (2023: $380 million) and decommissioning expenditure including cash provisioning for future decommissioning of $60 million (2023: $67 million).
· Adjusted EBITDAX1 of $1,152 million (2023: $1,151 million); gross profit of $754 million (2023: $765 million); profit after tax of $55 million (2023: loss of $110 million), including exploration costs writen off of $213 million (2023: $27 million).
· Free cash flow1 (FCF) of $156 million (2023: $170 million).
· Net debt1 at year end reduced to $1,452 million (2023: $1,608 million); cash gearing of net debt1 to adjusted EBITDAX1 of 1.3 times (2023: 1.4 times); liquidity headroom of $715 million (2023: $1,000 million).
· Audited 2P reserves at year end 2024 of 164.5 mmboe (2023: 212.2 mmboe), valued at $2.5 billion (NPV10), with the reserves reduction including 22.4 mmboe of Group production.
· Successful extension of the $250 million Revolving Credit Facility (RCF) to 30 June 2025.
· Successful resolution of the Ghana Branch Profits Remittance Tax (BPRT) arbitration, which removed a potential $320 million liability and endorses the sanctity of our Petroleum Agreements.
· Five new Jubilee wells (three producers and two water injectors) brought onstream, bringing the drill programme to an end approximately six months ahead of schedule with no recordable safety incidents, and saving over $88 million (gross) compared to the initial budget.
· Average FPSO uptime at Jubilee and TEN of 97%.
· Decommissioning activities in Mauritania accelerated and completed in 2024, ahead of schedule and below budget.
· Significant milestone reached with the Ghana Forestry Commission to implement a nature-based carbon offset programme.
2025 OUTLOOK and GUIDANCE
· Tullow has signed a binding heads of terms agreement with Gabon Oil Company for the sale of Tullow Oil Gabon SA, for a cash consideration of $300 million net of tax. Entering into the full sale and purchase agreement is targeted for the second quarter of 2025, with completion of the transaction expected around the middle of the year, subject to relevant governmental and regulatory approvals. See separate release: LINK
· Group working interest production expected to average 50 to 55 kboepd as previously announced, including c.6 kboepd of gas.
· Ghana drilling programme with Noble Venturer to commence in May 2025, with two Jubilee wells (one producer and one water injector) expected to come onstream in the third quarter of 2025.
· Completed 4D seismic survey in first quarter of 2025 to support future well locations and drive reserves growth.
· Capital expenditure of c.$250 million, allocated as follows: c.$160 million in Ghana, c.$70 million across the west African non-operated portfolio, c.$5 million in Kenya and c.$15 million of exploration expenditure.
· Decommissioning spend of c.$15 million for UK; c.$15 million cash provisioning for Ghana and Gabon.
· Further cost base optimisation underway, with expected c.$10 million saving reducing annual cash net G&A to c.$40 million.
· Cash taxes expected to be c.$150-200 million at $70-80/bbl with payments weighted c.60% to the first half of the year.
· Forecast free cash flow of c.$100-200 million at $70-80/bbl, including c.$50 million of overdue gas receipts in Ghana from 2024.
· Refinancing of the Group's capital structure targeted during 2025, following repayment of the 2025 Notes in early March 2025.
1. Alternative performance measures are reconciled on pages 34 to 37
Management Presentation - WEBCAST - 09:00
To access the webcast please use the following link and follow the instructions provided:
https://meetings.lumiconnect.com/100-695-362-491
A replay will be available on the website from midday on 25 March 2025:
https://www.tullowoil.com/investors/results-reports-and-presentations/
CHIEF EXECUTIVE OFFICER'S REVIEW
Overview
It is a privilege to be appointed Interim Chief Executive Officer (CEO). I have been a part of Tullow since 2011 and I care deeply about the business.
I would like to thank Rahul for his leadership over the past four years. During his tenure operational performance has improved significantly and, due to a reduced cost base and rigorous capital allocation process, net debt1 has reduced from $2.81 billion to $1.45 billion. I look forward to building on the strong foundations that have been laid by continuing to focus on delivering our transformative plans for the business in 2025 and beyond.
Key to our plans this year is the refinancing of upcoming debt maturities to strengthen our balance sheet. The process to further accelerate our deleveraging pathway continues with the strong progress towards realising the accretive cash sale of our Gabonese assets which is expected to close around the middle of the year.
In January 2025 we successfully resolved our claim in relation to the assessment of Ghana Branch Profits Remittance Tax (BPRT). This outcome, which determined that Tullow Ghana was not liable to pay the $320 million BPRT assessment previously issued by the Ghana Revenue Authority (GRA) and will have no future exposure to BPRT in respect of its operations under its Petroleum Agreements (PAs), affirmed our long held assessment and confidence in the PAs and removed a material overhang from our business. We continue to engage with the Government of Ghana on two further disputed tax claims, which were referred to the International Chamber of Commerce (ICC) in February 2023, with the aim of resolving these disputes on a mutually acceptable basis.
We have a clear plan to unlock material value from Tullow's unique pan-African platform. Tullow is a cash generative business and we are laying the foundations to grow our reserves base, accelerate our deleveraging pathway and deliver significant value accretion.
Operational performance
Our commitment to operational delivery is enabling us to manage our assets effectively. In the first half of 2024 the Ghana drilling programme was completed safely and ahead of schedule and resulted in 18 new Jubilee wells coming onstream since 2021.
2024 was a mixed year from a production perspective. Lower than anticipated production at Jubilee in the second half of 2024 was partially offset by strong performance at TEN. To address decline rates at Jubilee we have introduced a number of operational process improvements including power supply upgrades on the FPSO and measures to improve water injection reliability and increase capacity to 300 kbwpd.
Group working interest production for 2025 is expected to be 50-55 kboepd, including c.6 kboepd of gas production and inclusive of a two-week planned maintenance shutdown on the Jubilee field in the first half of the year, which will have a c.4% impact on Jubilee annual production. Two new Jubilee wells (one producer and one water injector) will be drilled, starting in May 2025, and are expected to come onstream in the third quarter of the year.
Ghana
Ghana continues to be the cornerstone of our operations. During the year, operational efficiency remained high with average facility uptime across the FPSOs averaging 97% and a combined average production rate of c.44.1 kbopd net. Five new Jubilee wells (three producers and two water injectors) were brought onstream during the first half of 2024, completing the Ghana drilling programme safely, and approximately six months ahead of schedule.
Gross oil production from the Jubilee field averaged c.87 kbopd (c.33.9 kbopd net). Production was impacted primarily by the performance of the J69 producer well, a lack of pressure communication from water injection, water injection performance and increased water cut in certain wells. The FPSO will undergo planned maintenance in the first quarter of 2025, during which we plan to implement upgrades to improve the reliability of the power supply and water injection consistency. Stable water injection combined with production optimisation activities is expected to reduce the rate of decline experienced in the second half of 2024.
Gross oil production from the TEN fields exceeded expectations, averaging c.18.5 kbopd (c.10.2 kbopd net) during the year, with Enyenra and Ntomme wells responding positively to both injection and production optimisation. We continue to explore options to maximise long term value from TEN, including a focus on the cost base to improve economics, and maturing further infill potential.
Net gas production in Ghana averaged 6.0 kboepd in 2024. The Jubilee interim Gas Sales Agreement (GSA) remains in place until the fourth quarter of 2025 at $3.00/mmbtu. We are planning to supply TEN gas during the Jubilee shutdown and continue to progress options to create a significant long-term revenue stream from the gas production and discussions continue regarding third party off-take opportunities.
Discussions with the Government of Ghana are ongoing in relation to receivables for the exported gas and we look forward to working with the new administration to settle the payments.
In 2025 we will undertake a short drilling programme in Ghana, with a primary focus on reducing natural decline. Furthermore, the state-of-the-art 4D seismic survey at the Jubilee and TEN fields will improve our understanding of the pressure and fluid movement in the reservoirs and is expected to support at least two further drilling campaigns on Jubilee within the current licence period, which will ultimately enable us to book more wells as reserves. Combined with the upward revision of TEN reserves related to substantial progress towards a material reduction in fixed costs, including in relation to the FPSO, and further 4D seismic assisted development drilling, there is a material opportunity ahead to sustain long-term production beyond the current life of field.
Non-operated and exploration portfolios
Production from the non-operated portfolio in 2024 was 10.6kbopd net. The production loss resulting from an incident at Simba was largely offset by improved production from the field when it came back onstream, as well as good performance from other onshore and offshore fields in the portfolio.
The Simba field in Gabon was shut down following an incident in March 2024 at the Perenco operated Becuna Platform, which tragically resulted in fatalities. The operator resumed operations in August 2024 after putting in place the necessary operational and engineering controls and obtaining the necessary regulatory approvals.
In Gabon, the Falcon NE infrastructure led exploration (ILX) prospect on the DE8 licence will be drilled during the first half of 2025. The Sarafina ILX well, drilled in 2024, found hydrocarbons and work is ongoing with the operator to evaluate the commercial potential.
In Côte d'Ivoire, options to realise value and mitigate capital exposure at the Espoir field are being explored ahead of licence expiry in 2026. We continue to assess options on the way forward for exploration licences CI-524 and CI-803.
In Argentina, we continue to assess options for these licences whilst mitigating capital exposure.
Decommissioning activities in the Banda/Tiof fields in Mauritania were accelerated in 2024 and have been completed ahead of schedule and below budget.
Kenya
Despite the delays associated with securing governmental approval and a strategic partner, Kenya remains a material option to drive value and growth and we are continuing to work with the Kenyan government to seek support for a Field Development Plan (FDP) and identify a long-term strategic partner, which is a key milestone to achieve a Final Investment Decision (FID).
Reserves and resources
At the end of 2024, audited 2P reserves were 164.5 mmboe (2023: 212.2 mmboe). The reserves reduction includes 22.4 mmboe of Group production during 2024 and a downward revision in Jubilee. Although recent Jubilee drilling results have encountered reservoir thicknesses close to prognosis, water has broken through in certain producing wells earlier than previously expected. This suggests that there still remain significant volumes of bypassed oil, which will be optimally targeted utilising the data produced by the 2025 4D seismic campaign. TEN reserves have been revised upwards as we progress a material reduction in fixed operating costs, especially on the FPSO, which extends the economic lifetime of the asset and facilitates further potential development through infill drilling.
Our asset base continues to have significant value, and as at 31 December 2024, the Group's audited 2P NPV10 was $2.5 billion.
The Group's audited 2C resources of 708.6 mmboe at the end of 2024 (2023: 745.0 mmboe) reflect the material opportunity we have to mature resources into reserves to realise sustained long-term production. In 2025, part of the Group's material 2C resources are expected to mature into 2P reserves with the support of the ongoing 4D seismic survey in Ghana and resulting identification of robust infill targets.
Sustainability
We are committed to building a better future through responsible oil and gas development. We recognise the ongoing need for oil and gas in Africa over the coming decades and we will continue to support our host countries to develop their natural resources whilst taking actions to minimise our environmental footprint and create value for all stakeholders including the communities where we operate.
As part of the double materiality assessment we conducted in 2024, we engaged a wide group of stakeholders to ensure we are focussed on the material economic, social and environmental impacts and issues that are most relevant to our business. We also refreshed how we communicate our sustainability approach to ensure it is clear for our stakeholders.
Our Net Zero by 2030 commitment is a core aspect of our strategy. During the year we implemented process improvements and modifications on our FPSOs in Ghana, and after all engineering works are complete, we expect routine flaring to be eliminated by the end of 2025.
As announced in July 2024, we have formed a strategic partnership with the Ghana Forestry Commission to begin full scale implementation of a nature-based carbon offset programme. This initiative aims to generate up to one million tonnes of certified carbon offsets per year to mitigate our residual, hard to abate emissions. The capability we have developed in addressing our emissions can also be applied to other carbon intensive assets across the continent to support low emission resource extraction.
Our community development programmes focused on improving education and employability in our host communities and creating opportunities for local employment and entrepreneurship. In February 2024, as part of our new 'Accelerating Progress Through Partnerships' community strategy, we announced the first multi-year Agriventures partnership with Innohub Foundation in Ghana. This two-year agriculture-focused programme will find and support entrepreneurs to set up and grow businesses capable of providing sustainable livelihoods.
To build on our existing commitment to minimise our environmental impact and protect biodiversity, in 2024 we set a "No Net Loss" nature ambition and completed a nature baseline assessment of our operated and non-operated assets to identify our nature-related impacts, risks and opportunities. In addition, we have also published our inaugural Taskforce on Nature-related Financial Disclosures (TNFD) report.
Outlook
In the year ahead our priorities are to progress our refinancing plan, optimise our production activities at Jubilee and TEN, and grow our reserve base. In particular we are leveraging advanced technologies and innovative approaches to minimise decline and extend the life of these fields and we have absolute confidence in the Jubilee field to deliver material cash flows and provide the business with optionality for returns and growth, once our net debt target of below $1 billion is reached.
The repayment of the 2025 Notes combined with our ongoing work to address our upcoming debt maturities will continue to strengthen our balance sheet.
In the near term we will maintain our focus on costs and financial discipline, prioritising high returns and focusing on investments that add value. As we continue to reduce our debt and optimise our capital structure, our balance sheet will grow stronger and we will be well-positioned to create lasting economic and social value for all stakeholders.
I would like to thank the whole Tullow team for all their hard work and dedication, they are the driving force behind the progress we have made in 2024 and they have shown tremendous resilience in recent months as we have embarked on additional cost optimisation, including redundancies associated with streamlining our cost base.
I would also like to thank our shareholders for their continued support, as we realise the potential of the business and generate value for all stakeholders.
Revenue
Sales oil volumes
During the year, there were 52,421 boepd (2023: 55,754 boepd) of liftings. The decrease was primarily driven by a reduction of two liftings in Gabon offset by an additional 650 kbbls lifted in Ghana, with 13 cargos lifted in Jubilee (2023: 13) and 4.5 in TEN (2023: 4).
Realised oil price ($/bbl)
The Group's realised oil price after hedging for the period was $76.4/bbl (2023: $77.5/bbl) and before hedging $80.2/bbl (2023: $84.3/bbl). Lower oil prices and lower hedged volumes subject to price caps compared to 2023 have resulted in a lower hedge loss which decreased total revenue by $74 million (2023: $139 million).
Gas sales
Included in Total Revenue of $1,535 million are gas sales of $54 million of which $48 million relates to Ghana. During the year, Tullow exported 33,660 mmscf (gross) of gas at an average price of $2.97/mmbtu in Ghana.
Cost of sales
Underlying cash operating costs
Underlying cash operating costs amounted to $272 million; $12.2/boe (2023: $293 million; $12.8/boe). Routine operating costs remain largely consistent with prior year. The decrease is primarily driven by non-recurring expenditure incurred in prior year, which included costs related to TEN shutdown and Jubilee riser remediation.
Depreciation, depletion and amortisation
DDA charges before impairment on production and development assets amounted to $438 million; $19.6/boe (2023: $431 million; $18.8/boe). The increase in DDA per boe was primarily driven by the reduction in Jubilee field 2P reserves during the current year offset by the impact of TEN field impairment recorded in 2023.
Overlift and oil stock movements
The Group recognised an overlift expense of $43 million (2023: overlift expense $109 million). The decrease in overlift expense is primarily due to lower liftings in Gabon in the current year, resulting from reduced oil production volumes compared to the prior year.
Administrative expenses
Administrative expenses of $53 million (2023: $56 million) have decreased in the current year despite the inflationary environment. This is largely due to reduction in one-off corporate project expenditures in the current year. Further cost base optimisation is underway for 2025, with expected c.$10 million saving reducing annual net G&A to c.$40 million.
Asset revaluation
Asset revaluation of $39 million relates to assets disposal as part of the assets swap with Perenco in Gabon (refer to Note 11 for further information).
Exploration costs written off
During 2024, the Group wrote off exploration costs of $213 million (2023: $27 million) primarily driven by Kenya where an extension of the Field Development Plan review date to June 2025 led to a reassessment of the risks associated with reaching Final Investment Decision and resulted in a $145 million impairment (refer to Note 8 for further details). Additionally, the carrying values of assets in Argentina and Cote d'Ivoire were written off by $39 million and $16 million, respectively, due to lack of planned expenditure on licences prior to expiry. Furthermore, $10 million was written off in relation to the Sarafina well at Simba, in Gabon.
Impairment of property, plant and equipment
The Group recognised a net impairment reversal on PP&E of $12 million in the current year (2023: Net impairment of $408 million) largely driven by cost savings from operational efficiencies and scope revision in the operated Mauritania decommissioning campaign.
Net financing costs
Net financing costs for the period were $274 million (2023: $286 million). This decrease is mainly attributable to lower interest on bonds due to a reduction in the outstanding balance, partially offset by higher interest on obligations under leases.
A reconciliation of net financing costs is included in Note 6.
Taxation
The overall net tax expense of $267 million (2023: $206 million) primarily relates to tax charges in respect of the Group's production activities in West Africa, reduced by deferred tax credits associated with future UK decommissioning expenditure, exploration write-offs and impairments.
Based on a profit before tax for the period of $322 million (2023: $96 million), the effective tax rate is 83.0% (2023: 214.3%). After adjusting for non-recurring amounts related to exploration write-offs, disposals, impairments, provisions and their associated deferred tax benefit, the Group's adjusted tax rate is 60.1% (2023: 70.2%). The effective tax rate is in line with the prior year, with the impact of non-deductible expenditure in Ghana and Gabon and no UK tax benefit arising from net interest and hedging expense of $206 million (2023: $167 million) being partially offset by deferred tax credits related to non-operated assets undergoing decommissioning and prior year adjustments.
The Group's future statutory effective tax rate is sensitive to the geographic mix in which pre-tax profits arise. There is no UK tax benefit from net interest and hedging expenses, whereas net interest and hedging profits would be taxable in the UK. Consequently, the Group's tax charge will continue to vary according to the jurisdictions in which pre-tax profits occur.
Adjusted EBITDAX
Adjusted EBITDAX for the year was $1,152 million (2023: $1,151 million) with a reduction in operating costs of $21 million, decrease in administrative expenses of $5 million, lower royalty taxes of $6 million and a decrease in overlift expense of $67 million, offset by lower revenue of $99 million.
Profit/(loss) for the year from continuing activities and earnings per share
The profit for the year from continuing activities amounted to $55 million (2023: $110 million loss). The increase in profit after tax was mainly driven by a reduction in impairments, recognition of asset revaluation gains and provision releases in the current year. Basic earnings per share was 3.7 cents (2023: 7.6 cents loss per share).
Capital investment
Capital expenditure amounted to $231 million (2023: $380 million) with $206 million invested in production and development activities of which $134 million invested in Jubilee mainly comprising of $103 million spend on drilling costs. Investments in exploration and appraisal activities are $25 million.
The Group's 2025 capital expenditure is expected to be c.$250 million and is expected to comprise Ghana capex of c.$160 million, West African Non-Operated capex of c.$70 million, Kenya capex of c.$5 million and exploration spend of c.$15 million.
Decommissioning
Decommissioning expenditure was $49 million in 2024 (2023: $67 million). The Group's decommissioning budget in 2025 is c.$30 million of which c.$15 million is cash provisioning for future decommissioning in Ghana and Gabon. Subject to programme scheduling, at the end of 2025 it is expected that c.$15 million of decommissioning liabilities in the UK will remain.
Derivative financial instruments
The Group has a material hedge portfolio in place to protect against commodity price volatility and to ensure the availability of cash flow for re-investment in capital programmes that are driving business delivery.
At 31 December 2024, the Group's hedge portfolio provides downside protection for c.60% of forecast production entitlements in the first half of 2025 with c.$59/bbl weighted average floors across all structures; while retaining strategic upside participation across for the same period, with only c.5% of forecast production entitlements capped with collars at a weighted average sold call of c.$92/bbl, and c.40% of forecast production entitlements secured with three-way collars with $92-$102/bbl call spreads. Similarly in the second half of 2025, the Group's hedge portfolio provides downside protection for c.55% of forecast production entitlements with c.$60/bbl weighted average floors across all structures; for the same period, c.15% of forecast production entitlements is capped at weighted average sold calls of c.$89/bbl while c.30% of forecast production entitlements is secured with three-way collars.
All financial instruments that are initially recognised and subsequently measured at fair value have been classified in accordance with the hierarchy described in IFRS 13 Fair Value Measurement. Fair value is the amount for which the asset or liability could be exchanged in an arm's length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets (Level 1). To the extent that market prices are not available, fair values are estimated by reference to market-based transactions or using standard valuation techniques for the applicable instruments and commodities involved (Level 2).
All of the Group's derivatives are Level 2 (2023: Level 2). There were no transfers between fair value levels during the year.
At 31 December 2024, the Group's derivative instruments had a net negative fair value of $12 million (2023: net negative $35 million).
Borrowings
On 15 May 2024, the Group made the annual prepayment of $100 million of the Senior Secured Notes due 2026.
The Group's total drawn debt reduced to $2,007.4 million, consisting of $492.5 million nominal value Senior Notes due in March 2025, $1,385.2 million nominal value Senior Secured Notes due in May 2026 and $129.7 million outstanding under the Glencore facility.
Management regularly reviews options for optimising the Group's capital structure and may seek to refinance, retire or purchase any of its outstanding debt from time to time through new debt financings and/or cash purchases or exchanges in the open market, privately negotiated transactions or otherwise.
Credit ratings
The Group maintains credit ratings with Standard & Poor's (S&P's) and Moody's Investors Service (Moody's).
Since December 2023, S&P has maintained the Group's corporate credit rating at B- with negative outlook, and the rating of the 2026 Notes at B- and the rating of the 2025 Notes at CCC+. Similarly, Moody's has maintained the Group's corporate credit rating at Caa1 with negative outlook, and the rating of 2026 Notes at Caa1 and the rating of the 2025 Notes at Caa2.
Underlying operating cash flow and free cash flow
Underlying operating cash flow for the year was $668 million (2023: $813 million), reflecting a decrease of $145 million. This was primarily driven by $148 million decline in cash revenue due to lower sales volumes, impact of reduced oil prices and timing of revenue payments. Additionally, cash taxes increased by $76 million compared to the prior year. These factors were partially offset by an $25 million reduction in cash operating costs, royalty taxes and administrative expenses and $26 million decrease in lease obligation repayments.
Free cash flow for the year decreased to $156 million (2023: $170 million). Underlying operating cashflow has reduced by $145 million, as outlined above. This decrease was largely offset by lower net cash used in investing activities, as well as reduced lease payments related to capital activities and decommissioning costs, which decreased by $55 million, $32 million, and $22 million, respectively. These reductions were due to the completion of the JSE campaign in Ghana and Chinguetti decommissioning campaign in Mauritania in 2023. Additionally, finance costs paid were $17 million lower in the current period.
Ghana tax assessments
On 24 December 2024, the BPRT Tribunal issued its ruling to the International Chamber of Commerce (ICC) which delivered its award on 2 January 2025 with regards to the BPRT arbitration with the Government of Ghana. The Tribunal determined that BPRT is not applicable to Tullow Ghana since it falls outside of the tax regime provided for in the Petroleum Agreements. This will mean that Tullow Ghana is not liable to pay the US$320 million BPRT assessment issued by the Ghana Revenue Authority and Tullow will have no future exposure to BPRT in respect of its operations under the Petroleum Agreements. Tullow has two further ongoing disputed tax assessments that relate to the disallowance of loan interest deductions for the fiscal years 2010 - 2020 and proceeds received by Tullow Oil plc under Tullow's corporate Business Interruption Insurance policy. Both were referred to international arbitration in 2023, with first hearings scheduled for 2025, however we continue to engage with the Government of Ghana, including the GRA, with the aim of resolving the assessments on a mutually acceptable basis.
Liquidity risk management and going concern
The Directors have extended the going concern assessment period to 31 May 2026, aligning with the maturity date of the 2026 senior secured bonds (2026 Notes). The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced, and sensitivities run for different scenarios covering key judgements and assumptions including, but not limited to, changes in commodity prices, different production rates from the Group's producing assets and different outcomes on ongoing disputes or litigation and the timing of any associated cash outflows. This assessment covers both the Group and the Company.
Management has applied the following oil price assumptions for the going concern assessment based on forward prices and market forecasts:
Base Case: $70/bbl for 2025; $70/bbl for 2026.
Low Case: $65/bbl for 2025; $65/bbl for 2026.
To consider the principal risks to the cash flow projections, a sensitivity analysis has been performed which is represented in the Low Case which management considers to be severe, but plausible, given the cumulative impact of the sensitivities applied. The most significant risk would be a sustained decline in oil prices. The analysis has been stress tested by including a 10% production decrease and 5% increased operating costs compared to the Base Case. Management has also considered additional outflows in respect of all ongoing litigations/arbitrations within the Low Case, with an additional $67 million outflow being included for the cases expected to progress in the going concern period. Based on the legal opinions received by management, the remaining arbitration cases are not expected to conclude within the going concern period or have remote outcomes, therefore no outflows have been included in that respect in the Low Case. In the event of negative outcomes after the going concern period, management would use all available court processes to appeal such rulings which, based on observable court timelines, would likely take in excess of a further year.
The Group is reliant on the continued provision of external financing. The undrawn $250 million revolving credit facility (RCF) and the $1.3 billion 2026 Notes fall due within the going concern period and both will require refinancing to ensure the Group has sufficient liquidity to meet its financial obligations. The Directors intend to complete a holistic refinancing of the existing debt capital structure during 2025. Discussions with banks and commodity traders to secure the refinancing are underway. A fundamental assumption in concluding that the Group is a going concern is a successful execution of a holistic refinancing. The successful execution of a holistic refinancing is subject to favourable macroeconomic and market conditions including but not limited to oil price, credit ratings and accessibility of High Yield Bond markets and is therefore outside the control of management.
In addition, a binding heads of terms agreement for the sale of Tullow Oil Gabon SA which holds 100% of Tullow's working interest in Gabon for cash consideration of $300 million net of tax has been entered into with Gabon Oil Company. Signing of a sale and purchase agreement is targeted for the second quarter of 2025. Completion of the transaction, which will be subject to relevant governmental and regulatory approvals, and receipt of the associated cash proceeds are assumed in June 2025 in the Base Case, with a three month delay assumed in the Low Case. Completion of this transaction will materially reduce the Group's net debt and is therefore expected to reduce the risk associated with the holistic debt refinancing. However, completion and timing of completion of this transaction are outside the control of management.
Implications and material uncertainties
The Base Case and the Low Case scenarios forecast a liquidity shortfall in May 2026 when the $1.3 billion 2026 Notes become due for payment, unless the Directors execute a holistic refinancing of the Group's debt capital structure in advance of that date. In addition, the Low Case scenario forecasts a liquidity shortfall at the end of June 2025, following expiry of the RCF and due to the assumed delay to the receipt of proceeds from the sale of Tullow Oil Gabon SA.
The Directors have initiated a process to execute a holistic refinancing based on proposals received from banks. The Directors believe this is achievable before the end of June 2025, noting the risks associated with wider market conditions. If this were not achieved by the end of June 2025 the Directors would continue to pursue such a refinancing in the second half of 2025 to alleviate the projected liquidity shortfall in May 2026 and believe this is achievable, again subject to market conditions.
In addition, if a holistic refinancing was not executed by the of June 2025 and receipt of proceeds from the sale of Tullow Oil Gabon SA was delayed (as assumed in the Low Case scenario), the Directors plan to enter into discussions with the lenders under the RCF to extend the maturity of the facility to align with the timing of completion of the holistic refinancing or the receipt of proceeds from the sale of Tullow Oil Gabon SA. Should this not be possible, the Directors will pursue alternative bridge financing from commodity traders or secure an alternative source of financing from private credit markets ahead of the projected shortfall at the end of June 2025. The Directors have received unsolicited offers of credit from such counterparties in excess of the need to alleviate the projected shortfall and would seek to engage with them and progress such offers, if required.
The Directors note that despite expressions of interest from private as well as public parties for participation in the holistic debt refinancing, implementing a holistic refinancing is outside the control of the Group. If the Directors were unable to implement a refinancing proposal, the ability of the Group to continue trading would depend upon the Group being able to negotiate a financial restructuring proposal with its creditors and, if necessary, that proposal being approved by shareholders. Whilst the Board would seek to negotiate such a financial restructuring proposal with its creditors, it is possible that the creditors would not engage with the Board in those circumstances. There would therefore be a possible risk of the Group entering into insolvency proceedings, which the Directors consider would likely result in limited or no value being returned to shareholders.
The Directors have concluded that 1) implementing a holistic refinancing by the end June 2025 or by May 2026 at the latest and 2) obtaining sufficient liquidity to cover the expiration of the RCF at the end of June 2025, if a holistic refinancing is not implemented by that date, by extending the maturity of the facility or by completing the sale of Tullow Oil Gabon SA and receipt of proceeds from the transaction or with alternative bridge financing, are outside the control of the Group. These are therefore material uncertainties that may cast significant doubt over the Group and the Company's ability to continue as a going concern. Notwithstanding these material uncertainties, the Board has confidence in the Group's ability to implement a holistic refinancing or extend the RCF or either complete the sale of Tullow Oil Gabon SA including receipt of proceeds or seek an alternative source of financing before the end of June 2025. This is based on the plans in place on the holistic refinancing, the ongoing support of existing lenders under the RCF, the binding heads of terms agreement signed with Gabon Oil Company for the sale of Tullow Oil Gabon SA and the unsolicited offers of liquidity received from other sources of finance and credit providers. This is in the context of the underlying value and cash generation of the Group's producing fields to support future debt service and repayment. On this basis the Board have prepared the Financial Statements on a going concern basis. The Financial Statements do not include the adjustments that would result if the Group and the Company were unable to continue as a going concern.
Events since 31 December 2024
On 14 February 2025, Richard Miller was appointed as Interim Chief Executive Officer (CEO). Rahul Dhir stepped down as Director from the Board of Tullow Oil plc.
On 3 March 2025, the Group settled the 2025 Notes upon maturity with a payment of $510 million, comprising a $493 million principal repayment and $17 million final coupon. This payment was partially funded through a $270 million drawdown from the Secured Notes Facility, with the remainder sourced from cash at bank. Following the $270 million drawdown, the Secured Notes Facility was fully drawn at $400 million.
On 24 March 2025, Tullow announced that it had signed a binding heads of terms agreement with Gabon Oil Company for the sale of Tullow Oil Gabon SA, which holds 100% of Tullow's working interests in Gabon for a total cash consideration of $300 million net of tax. Signing of a sale and purchase agreement is targeted for the second quarter of 2025, with completion of the transaction and receipt of funds expected around the middle of the year, subject to receipt of relevant governmental and regulatory approvals.
The transaction is a corporate sale of Tullow's entire Gabonese portfolio of assets, representing c.10 kbopd of 2025 production guidance and c.36 million barrels of 2P reserves. Conditions precedent for the completion of the Transaction include all necessary approvals (including from government ministries), CEMAC Competition Commission approval and Tullow's processing of the 2024 dividend in compliance with Gabonese requirements.
This is a non adjusting event as at 31 December 2024 as defined by IAS 10 'Events after the Reporting Period'.
There have not been any other events since 31 December 2024 that have resulted in a material impact on the year end results.